Toronto: When the Ontario Power Authority suggested in its power system plan last fall that enabler lines should be treated like network assets, many people assumed that it would be a relatively simple matter to determine who would pay for these lines and how. But the wide range of participation in the consultation process initiated by the Ontario Energy Board has opened up a full-scale review of the issue, highlighting a host of related issues that the participants feel need to be considered at the same time. As a result, the Transmission Connection Cost Responsibility Review has widened and many participants are looking at it as something with potentially long-term implications beyond its apparent cost-related boundaries.
Perhaps most significant, the Cost Responsibility Review has become a forum to address a key question that has been unresolved since Ontario’s market design was first released: How should the developer of new common carrier facilities be selected? Many participants including APPrO believe that the question of ownership is less significant than the separate questions of who will pay and what regulatory rules will be applied to transmission developers, including the rules governing the provision of preliminary information necessary for generators to bid on power projects. Nonetheless, the selection of a developer is a pre-requisite for starting certain parts of the process, because certain approval applications can’t begin in earnest until the developer is known. APPrO Executive Director Jake Brooks says, “Although many of the necessary approvals can be obtained through existing OEB procedures before reaching final closure on ownership, generators will not have complete assurance on the timelines for new enabler lines until the process for selecting a transmission developer is firmly established.” As noted below, the certainty of timing for connection to new enablers has become a major concern for generators.
Many participants think that the OEB should take on the role of selecting a developer for new enabler lines. However, even that is open to question, as the argument can be made that the OPA is in a better position to choose between developers, given that it already operates a number of competitive and non-competitive procurement processes that conform to public directives and plans. Setting up a similar capacity at the OEB might be somewhat duplicative, but would have the advantage of legislated quasi-judicial structures designed for making complex public interest decisions, such as whether transmission capacity and line configurations might have implications for long term service access from common carriers. In the end it is possible that the process may result in a combined effort, with the OPA doing a lot of the financial comparisons, and the OEB making the final judgment on the appropriateness of a given developer. Either way the issue is decided, APPrO has said it is important to arrive at a firm and workable conclusion on the procedures as soon as possible. In fact, APPrO has recommended that the OEB initiate an industry consultation jointly with the OPA to consider how best to select developers and manage the development stage of enabler projects.
These are not the only issues arising in the review process, of course. In addition to who owns and who pays, many in the industry are also concerned about a range of issues that affect overall costs, timing and the certainty of connection for new generators. For example, in the process of resolving the central questions in the OEB’s cost responsibility review, some observers believe the Board will have to grapple with such questions as:
1. Which risks should be left with the transmission developer, which with the transmission builder, which with the generator, and that need to be socialized across the entire network asset pool?
2. What is the best way to determine the appropriate size of the line to be approved, so that it is neither overbuilt, nor risks the potentially more serious consequences of shutting in desirable energy resources because of under-sizing the line to a potential generation development zone?
3. Is the practice of exposing transmitters to the risk of non-recovery (as a means of instilling market discipline) appropriate in this situation, when timing is such an issue?
4. How can the various approval processes for new transmission be co-ordinated with the development of generation so that new generation projects aren’t left sitting on a fully-executed contract for years, waiting for the transmission line process to be completed?
5. What other issues of co-ordination between agencies might be addressed to reduce unnecessary uncertainty, duplication or delays in the overall process?
Although the OEB may need to consider some aspects of these questions in making its decision on cost responsibility, other aspects of the issues will probably become much easier to resolve once the decision on cost responsibility has been finalized.
The current approval process for a new enabler line is about seven years long. Many generators are highly concerned about that, because this could mean waiting years before they can connect their projects to supply the grid. The OPA believes that with changes to socialize at least the initial development costs, it is possible to have the enabler lines proposed in the IPSP built by 2015. However, that assumes that everything stays on schedule – and some experts question whether such an estimate is realistic. See the sidebar for a breakdown of the steps anticipated in the 7-year process of getting a new enabler line into service.
As if that wasn’t enough to deal with, the Canadian Wind Energy Association and others are raising a broad question about how to deal with the potential that an enabler line will over time take on different functions. For example, if loads connect to an enabler, as would be logical in certain circumstances, the current model would not provide any ready rules or procedures on how this impacts the line designation and the recovery of costs. And even more complex, if the enabler line is eventually connected back to the overall network at a second point, it could become functionally indistinguishable from a standard network asset, and all the rules pertaining to treatment of non-network enablers might become irrelevant in such a case. Under some options this might create an unexpected obligation for the network to refund capital contributions made by original users of the enabler. “It is only now becoming apparent how much of the structure for new transmission development was left open in the original market design,” Brooks says.
Subsequent to the setting of the OEB’s scope for this consultation, the Independent Electricity System Operator and Hydro One have raised a related concern: How to pay for upgrades to the distribution system that are becoming necessary to accommodate the renewable energy standard offer projects the OPA is signing up. This kind of question may have to be dealt with in a later phase of work, focused on analogous cost responsibility issues at the distribution level. (See related story “IESO sees need to finance VARs management,” page 32.)
The Ontario Energy Board issued a staff discussion paper on July 8 focusing on transmission connection costs for enabler lines, and held a question and answer meeting on July 22. Four options were proposed, but according to APPrO and others, only two of the options addressed the problem of how to develop enablers in an optimal manner that benefits all participants and the province. Intervenors in the proceeding were given until mid-August to respond. A wide range of stakeholders are involved including APPrO, AMPCO, CanWEA, OWA, the OPA, OPG, VECC and others.
APPrO’s submission to the OEB went into the issues in some detail, and is available on APPrO’s website. APPrO recommended treating enabler lines as network facilities that are primarily required to meet the government’s renewable energy targets, but which would also provide system-wide benefits to all electricity consumers and allow other generators and load customers to connect to what is essentially an extension of the transmission grid.
The OPA, when it originally raised these issues in the IPSP last year, was suggesting primarily that the initial development costs be socialized. For more information, see the OPA IPSP filing, Exhibit E, Tab 2, schedule 2, page 14.
For more information, go to http://www.oeb.gov.on.ca/OEB/Industry%20Relations/OEB%20Key%20Initiatives/Transmission%20Connection%20Cost%20Responsibility%20Review/Transmission%20Connection%20Cost%20Responsibility%20Review. Or visit the OEB website at http://www.oeb.gov.on.ca/ and enter the following code in the Search field: EB-2008-0003, then scroll down to “Transmission Connection Cost Responsibility Review.”
See also the following related articles: “Transmission cost responsibility to be discussed at the OEB,” IPPSO FACTO, February 2008 and “What is the regulatory gap and how can it be filled?” IPPSO FACTO, December 2007.